In the production of oil from subterranean formations, it is usually possible to recover only a small fraction of the total oil present in the formation by so-called primary recovery methods which utilize only the natural forces present in the reservoir. To recover oil beyond that produced by primary methods, a variety of supplemental production techniques have been employed. In these supplemental techniques, commonly referred to as secondary recovery operations, a fluid is introduced into the oil-bearing formation in order to displace oil to a production system comprising one or more production wells. The displacing or "drive" fluid may be an aqueous liquid such as brine or fresh water, a gas such as carbon dioxide, steam or dense-phase carbon dioxide, an oil-miscible liquid such as butane, or an oil and water-miscible liquid such as an alcohol. Often, the most cost-effective and desirable secondary recovery methods involve the injection of an aqueous or carbon dioxide flooding medium into an oil-bearing formation, either alone or in combination with other fluids. In practice, a number of injection and production wells are used in a given field. These are generally arranged in conventional patterns such as a line drive, a five spot or inverted five spot, or a seven spot or inverted seven spot.
In the use of the various fluid flooding techniques, it has become a common expedient to add various polymeric thickening agents to the drive fluid to increase its viscosity to a point where it approaches that of the oil which is desired to be displaced, thus improving the displacement of oil from the formation. The polymers used for this purpose are often said to be used for "mobility" control.
Another problem encountered in fluid flooding is that certain injected drive fluids may be much lighter than the reservoir fluids and thus separate by gravity, rising toward the top of the flowing region and resulting in the bypassing of the lower regions. This phenomena is known as gravity override.
Also encountered in the use of the various flooding techniques is a problem brought by the fact that different regions or strata may have different permeabilities. When this is encountered, the drive fluid can preferentially enter regions of higher permeability due to their lower resistance to flow. The regions of lower permeability, where significant volumes of oil often reside, are left unswept and do not benefit from the use of such secondary or tertiary recovery techniques.
It is therefore often desirable to plug the regions of high permeability, or "thief" zones, either partly or entirely, so as to divert the drive fluid into regions of lower permeability. The mechanical isolation of these thief zones has been tried but vertical communication among reservoir strata often renders this method ineffective. Physical plugging of the high permeability regions by cements and solid slurries has also been tried with varying degrees of success; however, these techniques have the drawback that still-productive sites may be permanently closed.
As a result of these earlier efforts, the desirability of designing a viscous slurry capable of sealing off the most permeable layers so that the drive fluid would be diverted to the underswept, "tighter" regions of the reservoir, became evident. This led to the use of oil/water emulsions, as well as gels and polymers for controlling formation permeability. This process is frequently referred to as "profile" control, a reference to the control of the vertical permeability profile of the reservoir. Profile control agents which have been proposed include oil/water emulsions and polymeric gels, with polymeric gels being the most extensively applied in recent years.
There are a variety of materials commercially available for profile control, all of which perform differently and have their own, often unique limitations. Among the many polymers examined are polyacrylamides, polysaccharides, celluloses, furfural-alcohol and acrylic-epoxy resins, silicates and polyisocyanurates. For polyacrylamides, see J. C. Mack, "Process Technology Improves Oil Recovery," SPE 7179, SPE Rocky Mountain Regional Meeting, May 17-19, 1978. Cody, Wyo.; W. G. Routson, M. Neale, and J. R. Penton, "A New Blocking Agent for Water Channeling," SPE 3992, 47th Annual Fall Meeting of SPE-AIMR, Oct. 8-11, 1972, San Antonio; D. Sparlin, "An Evaluation of Polyacrylamides for Reducing Water Production," J. Pet. Tech., 906-914, August, 1976; and G. P. Willhite and D. S. Jordan, "Alteration of Permeability in Porous Rocks with Gelled Polymers," 1981 ACS Meeting, Aug. 23-28, New York, Polymers Preprints. For polysaccharides, see R. W. Farley, J. F. Ellebracht, and R. H. Friedman, "Field Test of Self-Conforming Oil Recovery Fluid," SPE 5553, 50th Annual Fall Meetings of SPE-AIME, Sept. 28-Oct. 1, 1975, Dallas. For furfural-alcohol and acrylic/epoxy resins, see R. H. Knapp, M. E. Welbourn, "Acrylic/Epoxy Emulsion Gel System for Formation Plugging: Laboratory Development and Field Testing for Steam Thief Zone Plugging," SPE 7083, Symposium on Improved Oil Recovery, Apr. 16-19, 1978, Tulsa; and P. H. Hess, C. O. Clark, C. A. Haskin and T. R. Hall, "Chemical Method for Formation Plugging," J. Pet. Tech., 559-564, May, 1971. For polyisocyanurates, see C. T. Presley, P. A. Argabright, R. E. Smith, and B. L. Phillips, "A New Approach to Permeability Reduction," SPE 4743, Symposium on Improved Oil Recovery, Apr. 22-24, 1974 Tulsa).
A major part of the work conducted in this area has dealt with polyacrylamides. Polyacrylamides have been used both in their normal, non-crosslinked form as well as in the form of crosslinked metal complexes, as described, for example, in U.S. Pat. Nos. 4,009,755, 4,069,869 and 4,413,680. In either form, the beneficial effects derived from these polyacrylamides seem to dissipate rapidly due to shear degradation during injection. To overcome this problem and achieve deeper penetration into the reservoir, dilute solutions of these polymers have sometimes been injected first and then complexed in-situ. For example, in one such process, three sequential injection steps are employed: cationic polyacrylamides are injected first for strong adsorption and anchoring onto the generally anionic sites of the reservoir rock surfaces, followed by chelation with aluminum ions provided by aluminum citrate or with chromium ions generated by the in-situ reduction of dichromate ions and finally, anionic polyacrylamides are injected for the formation of the desired cationic polymer-metal ion-anionic polymer complexes (J. E. Hassert, and P. D. Flemming, III, "Gelled Polymer Technology for Control of Water in Injection and Production Wells," 3rd Conferences on Tertiary Oil Recovery, University of Kansas, Lawrence, 1979).
In general, there are two ways to deliver polymer gels into the formation. The first method is to inject gelled polymer into the formation. This is the so-called surface gelation method. The advantage of this method is that the polymer will enter the loose zone in preference to the tight zone because of the high viscosity of gelled polymer. The other advantage is that gelation is ensured because the gel is prepared on the surface. The disadvantage of this method is that the polymer gel will probably not penetrate far enough to block a high pore volume of the designated zone at low pumping pressures and low pumping rates, especially when the pressure drop occurs rapidly within a small radius of the injection wellbore. At high pumping pressures and flow rates, there are increased risks of fracturing the reservoir and degrading the gel structure by high shear forces.
The second method is the so-called in-situ gelation method. One in-situ gelation technique is carried out by injecting separate slugs of polymer, one containing an inactive crosslinker (such as dichromate) and the other activator (reducing agents such as thiourea and bisulfite), sequentially into the reservoir. Gelation occurs when the two parts meet in the reservoir. With this technique, shear degradation is reduced and the penetration of polymer is improved because of the lower viscosity of the ungelled polymer. However, a disadvantage of this method is that there is no guarantee that the two slugs of treatment will be placed in the same area and mixed well enough to form a strong gel. To avoid this problem, it would be advantageous to inject the constituents of the gel-forming composition simultaneously, or after first premixing them prior to injection. However, the majority of gel-forming compositions known in the art are relatively fast acting in that they begin to gel rather quickly. The proper placement of large volume treatments can be inhibited by such fast-acting gels as the treatment flow path begins to plug.
Profile control treatments must be properly performed for maximum effect; large treatments, injected over many days, are often needed. In most reservoirs thief zones are not isolated from other zones. If a small amount of the thief zone is plugged with a profile control treatment, injected fluids may be diverted only for a few feet away from the wellbore and soon find their way back into the thief zone. Much larger profile control treatments, while often suffering from the same problem, will recover much more oil because a much larger volume of the reservoir will be swept before the fluids flow back into the thief zone.
In thick reservoirs or those with large well spacing, many days are often required to pump the profile control treatment into place due to the large volume of injectant necessary. Also a factor is that the pumping rate to place a profile control gel is usually limited by the parting pressure of the reservoir. These factors require in-situ gelling profile control formulations to crosslink very slowly. In the simplest case, if 16 days are needed to place the treatment, it must be designed to gel in 16 days. This means that the well should be shut-in (taken out of the producing mode), for 16 days after injection is complete so the whole treatment will gel before returning the well to fluid flood injection or production. This results in a tremendous waste of time as well as money from lost oil production.
Therefore, what is needed is a method for effectively treating a large reservoir with a profile control agent which minimizes shut-in time after treatment, yet permits the placement of a large volume of such agent within the reservoir.
Accordingly, it is an object of the present invention to provide a method of attaining improved profile control of subterranean oil-bearing stratified reservoirs.
It is another object of the present invention to make practical fluid flooding enhanced oil recovery operations in larger reservoirs from the perspective of cost and efficiency.
It is yet another object object to minimize reservoir shut-in time following the placement of a profile control treatment.
Other objects, aspects and the several advantages of the present invention will become apparent to those skilled in the art upon a reading of the specification and the claims appended thereto.